During the drilling of a wellbore, various fluids are typically used in the well for a variety of functions. The fluids may be circulated through a drill pipe and drill bit into the wellbore, and then may subsequently flow upward through wellbore to the surface. During this circulation, the drilling fluid may act to remove drill cuttings from the bottom of the hole to the surface, to suspend cuttings and weighting material when circulation is interrupted, to control subsurface pressures, to maintain the integrity of the wellbore until the well section is cased and cemented, to isolate the fluids from the subterranean formation by providing sufficient hydrostatic pressure to prevent the ingress of formation fluids into the wellbore, to cool and lubricate the drill string and bit, and/or to maximize penetration rate.
In most subterranean drilling procedures the drilling fluid takes the form of a “mud,” i.e., a liquid having solids suspended therein. The solids function to impart desired properties to the drilling fluid such as to increase the density thereof in order to provide a suitable hydrostatic pressure at the bottom of the well. The drilling mud may be either a water-based or an oil-based mud. One of skill in the art should appreciate that an oil-based mud is typically based on a combination of oil and water in the form of an invert (water in oil) emulsion.
Drilling muds may further include polymers, biopolymers, clays and organic colloids to obtain the required viscous and filtration properties. Heavy minerals, such as barite, manganese oxides, hematite, iron oxides, calcium carbonate, may be added to increase density. Solids from the formation are incorporated into the mud and often become dispersed in the mud as a consequence of drilling. Further, drilling muds may contain one or more natural and/or synthetic polymeric additives, including polymeric additives that affect the rheological properties (e.g., plastic viscosity, yield point value, gel strength) of the drilling mud, and polymeric thinners and flocculants.
Polymeric additives included in the drilling fluid may act as fluid loss control agents. Fluid loss control agents, such as starch, xanthan gums, synthetic polymers and the like are designed to prevent the loss of fluid to the surrounding subterranean formation by reducing the permeability of filter cakes formed on the newly exposed rock surface. In addition, polymeric additives may be employed to impart sufficient carrying capacity and thixotropy to the mud to enable the mud to transport the cuttings up to the surface and to prevent the cuttings from settling out of the mud when circulation is interrupted.
Many drilling fluids may be designed to form a thin, low-permeability filter cake to seal permeable subterranean formations penetrated by the drill bit. The filter cake is essential to prevent or reduce both the loss of fluids into the subterranean formation and the influx of fluids present in the subterranean formation. Upon completion of drilling, the filter cake may stabilize the wellbore during subsequent completion operations such as placement of a gravel pack in the wellbore. Filter cakes often comprise bridging particles, cuttings created by the drilling process, polymeric additives, and precipitates. One feature of a drilling fluid is to retain these solid and semi-solid particles as a stable suspension, free of significant settling over the time scale of drilling operations.
The selection of the type of drilling fluid to be used in a drilling application involves a careful balance of both the good and bad characteristics of the drilling fluids in the particular application and the type of well to be drilled. The primary benefits of selecting an oil-based drilling fluid, also known as an oil-based mud, include: superior hole stability, especially in shale formations, formation of a relatively thinner filter cake than the filter cake achieved with a water-based mud, excellent lubrication of the drilling string and downhole tools, and penetration of salt beds without sloughing or enlargement of the hole, as well as other benefits that should be known to one of skill in the art.
An especially beneficial property of oil-based muds is their excellent lubrication qualities. These lubrication properties permit the drilling of wells having a significant deviation from vertical, as is typical of off-shore or deep water drilling operations or when a horizontal well is desired. In such highly deviated holes, torque and drag on the drill string are a significant problem because the drill pipe lies against the low side of the hole. Often the torque that must be applied to the drill string is high when water-based muds are used. In contrast, oil-based muds provide a thin, slick filter cake that helps to reduce the torque on the drill pipe, and thus the use of the oil-based mud can be justified.
Despite the many benefits of using oil-based muds, they have disadvantages. In general, the use of oil-based drilling fluids and muds have high initial and operational costs. These costs can be significant depending on the diameter and depth of the hole to be drilled. However, the higher costs can often be justified if the oil-based drilling fluid prevents the caving in or hole enlargement that can greatly increase drilling time and costs.
Disposal of oil-coated drilling cuttings is another primary concern, especially for off-shore or deep-water drilling operations. In these latter cases, the cuttings must be either washed clean of the oil with a detergent solution that also must be disposed, or the cuttings must be shipped back to shore for disposal in an environmentally safe manner. Another consideration that must be taken into account is the local governmental regulations that may restrict the use of oil-based drilling fluids and muds for environmental reasons.
Oil-based muds typically contain some water, either from the formulation of the drilling fluid itself, or water may be intentionally added to affect the properties of the drilling fluid or mud. In such water-in-oil type emulsions, also known as invert emulsions, an emulsifier is used to stabilize the emulsion. In general, the invert emulsion may contain both water soluble and oil soluble emulsifying agents. Typical examples of such emulsifiers include polyvalent metal soaps, fatty acids and fatty acid soaps, and other similar suitable compounds that should be known to one of ordinary skill in the art.
After any completion operations have been accomplished, removal of filter cake (be it water based or oil based) remaining on the sidewalls of the wellbore may be necessary. Although filter cake formation is essential to drilling operations, the filter cake can be a significant impediment to the production of hydrocarbon or other fluids from the well if, for example, the rock formation is plugged by the filter cake. The filter cake can also be a significant impediment to using the well as an injection well through which gas (nitrogen, carbon dioxide, natural gas and the like) or aqueous fluids may be injected into the formation in a secondary or tertiary recovery process. Because filter cake is compact, it often adheres strongly to the formation and may not be readily or completely flushed off of the face of the formation by fluid action alone.
The removal of water-based filter cake has been conventionally achieved with water based treatments that include: an aqueous solution with an oxidizer (such as persulfate), a hydrochloric acid solution, organic (acetic, formic) acid, combinations of acids and oxidizers, and aqueous solutions containing enzymes. For example, the use of enzymes to remove filter cake is disclosed in U.S. Pat. No. 4,169,818. Chelating agents (e.g., EDTA) have also been used to promote the dissolution of calcium carbonate. According to traditional teachings, the oxidizer and enzyme attack the polymer fraction of the filter cake and the acids typically attack the carbonate fraction (and other minerals). Generally, oxidizers and enzymes are ineffective in breaking up the carbonate portion, and acid are ineffective on the polymer portions.
One of the most problematic issues facing filter cake removal involves the formulation of the clean-up solutions. For example one of the more common components in a filter cake is calcium carbonate, a clean-up solution would ideally include hydrochloric acid, which reacts very quickly with calcium carbonate. However, while effective in targeting calcium carbonate, such a strong acid is also reactive with any calcium carbonate in the formation (e.g., limestone), and it may be reactive or chemically incompatible with other desirable components of the clean-up solution. Further the clean-up solution can permeate into the formation, resulting in unanticipated losses, damage to the formation that subsequently result in only a partial clean-up or loss of well control.
The use of traditional emulsifiers and surfactants in the invert drilling fluid systems that formed the filter cake can further complicate the clean-up process in open-hole completion operations. Specifically, fluids using traditional surfactant and emulsifier materials may require the use of solvents and other surfactant washes to penetrate the oil-based filter cake and reverse the wettability of the residual particles. Invert emulsion drilling fluids that exhibit an acid induced phase change reaction have been previously described in U.S. Pat. Nos. 6,218,342, 6,790,811, and 6,806,233 and U.S. Patent Publication No. 2004/0147404, the contents of which are incorporated by reference in their entirety. The fluids disclosed in these references all contain one form or another of an ethoxylated tertiary amine compound that stabilizes the invert emulsion when it is not protonated. Upon protonation of the amine compound, the invert emulsion reverses and becomes a regular emulsion. In most cases, deprotonation of the amine compound allows for the reformation of an invert emulsion. The clean-up of wells drilled with this invert emulsion drilling fluid may be simplified by using a wash fluid that contains an acid in a concentration sufficient to protonate the amine surfactant in the drilling fluid (and hence the filter cake).
Weighting agents are utilized to increase the density of the clean up solutions. The weighting agents enable the solutions to match the density of the drilling fluid and provide sufficient hydrostatic head so that the well can remain under control. High density brines containing salts of alkali and alkaline earth metals are examples of such weighting agents.
One drawback to the using so many different chemicals is the need to mix them at the wellsite. Mixing fluids at the wellsite is typically more expensive and inconvenient than offsite mixing. Space and facilities are limited at the wellsite. Consequently, there is a need for clean-up fluids that minimize the need to mix chemicals at the wellsite.
Unintended side effects can also arise from combining the various chemicals used to form the clean-up solutions and using these solutions downhole to remove filter cakes. One such side effect is precipitation in the wellbore. When precipitants form in the wellbore, they can clog the pumps and equipment intended to circulate the fluids and remove the filter cake. Calcium formate is one example of a precipitant that may form in processes for removing filter cakes. Accordingly, there also exists a need for effective clean-up solutions and processes that avoid the formation of precipitants.